This disclosure relates in general to robust and effective methods and systems for obtaining a sample of a liquid and/or a gas phase from a multiphase mixture flowing in a pipeline, where the multiphase mixture comprises oil and/or a gaseous hydrocarbon and the pipeline is configured for the transport of the oil and/or gaseous hydrocarbon. In certain aspects of the present invention, after obtaining the sample of the liquid or gas phase of the multiphase mixture, sensing devices, meters, sensor systems or the like may be used to analyze the properties of the collected liquid or gas phase sample.
It is desirable during the production and/or transport of oil and gas to carry out measurements to determine the properties of a multiphase mixture flowing in a hydrocarbon pipeline where the multiphase flow may consist of a combination of oil, water, gas and/or the like. With regard to the liquid phase of the multiphase mixture, measurement of the properties of the oil and/or water, including among other things the amount of the oil and/or water in a hydrocarbon transporting pipeline is often highly desirable so as to control and regulate hydrocarbon production. For example, it may be important to measure oil being produced by not only an oilfield, but also individual oil wells associated with the oilfield. Measurements may be necessary/desirable in order to determine the water and/or the gas content of the flow being produced from individual oil wells—for production analysis, etc—and/or to allocate production amounts to individual rights owners.
The early detection of water is an important measurement for subsea gas condensate wells where inhibitors may be added to prevent the formation of scale and hydrates in the pipeline downstream of the well head. In such cases, expensive inhibitors may be pumped into the pipeline from the start of hydrocarbon production, the quantity of fluid being determined from reservoir models. To manage the use of the inhibitors, the detection and quantification of the water can result in significant cost savings. Furthermore, in aging oil wells where the gas-volume fraction (GVF) can be very high (GVF >95%), the quantity of oil in the flow line determines the economics of the well.
It is, however, in general, very difficult to obtain measurements when the oil and/or water are flowing simultaneously with gaseous components through the pipeline. The problems associated with taking measurements arise, from among other things, the distribution of the different phases in the pipe—the phases may form different arrangements temporally and spatially—both axially and radially in the pipe. These different arrangements of the multiple phases may create, among other things, nonlinear responses—with the measuring system.
Flow of the multiphase fluid in the pipe may consist, among other flow designations, of a continuous phase—normally, liquid flow—or a discontinuous phase—normally, gas flow. In the continuous phase, the flow may be a continuous oil flow and the flowing oil may contain water droplets. Such flow, being primarily made up of a hydrocarbon substance, may, in general, be marked by low electrical conductance characteristics. In the alternative, the flow may be a continuous water flow with oil droplets distributed in the continuously flowing water. In such situations, the water, which may also have varying degrees of salinity, may provide that the flowing mixture has electrically conductive characteristics that change with time due to water injection or breakthrough, especially in contrast to the oil continuous situation.
With regard to the gaseous components of the multiphase fluid, the gaseous components may be distributed in large volumes or pockets in the multiphase fluid as gas churns or slugs, or may be distributed as small bubbles in the liquid phase, often referred to as bubble flow. Furthermore, under high pressure, such as found down-hole, gas in the multiphase fluid may be dissolved in the oil phase. When there are large volumes of gas in the pipeline the gas may govern the multiphase fluid flow and cause the oil and water phase to be pushed back to the pipe wall. In this case, often referred to as annular flow, the oil/water fluid mixture may move at a low velocity along the pipe wall. Additionally annular-mist flow may occur when gas flow dominates the multiphase flow in the pipe (and in mist flow, neither the water phase nor the oil phase is continuous). In such annular-mist flow, gas-carrying droplets of oil or water may move up the center of the pipe at high velocity while the remaining oil or water flows up along the pipe walls at low velocity.
In general, the liquid—which may be formed from multiple liquids mixed together—moves with a common velocity through the pipeline. However, in low flow velocity situations oil and water in the multiphase mixture may become partially or even completely separated. In such situations, the water and oil may travel at different velocities through the pipeline. For a non-horizontal pipe, the lighter oil may move up the pipe faster than the heavier water and cause small water drops to form that may in turn aggregate to form larger drops or slugs that may reach pipe diameter. This type of flow is often referred to as slug flow. The difference in velocity of the oil and water moving through the pipe is often referred to as “slip”. Because gas has a substantially lower density than oil/water or a mixture of the two, a larger slip will occur between the gas and the liquid phases.
These flow properties of the multiphase mixture in the pipeline make it difficult to sample and/or measure properties of the different phases of the multiphase mixture, including the properties of the liquid phase. Sampling of the phases of the multiphase mixture are troublesome in that, generally, they require integration of equipment with the pipeline and this equipment may interfere with the efficacy and efficiency of the pipeline and, additionally, to isolate a liquid phase of the multiphase mixture may require complex equipment that may among other things, require maintenance and/or may need monitoring and controlling. As such, much of the focus of the hydrocarbon industry has focused on sensors, meter and/or the like that can directly measure properties of the multiphase mixture without sampling one or more of the phases of the multiphase mixture. Examples of some of such meters and/or sensors are described below.
U.S. Pat. No. 4,289,020 (“the '020 patent) describes a system for the limited purpose of measuring water-cut in a multiphase fluid when gas is present. The '020 patent does not disclose or teach measuring actual multiphase flow in a pipe and, consequently, it does not disclose how to address the issues associated with such measurements. The '020 patent discloses using a combined transmission-microwave and gamma-ray density measuring system to measure the water-cut in the multiphase fluid with gas present. In the system, the microwave and gamma ray beams are configured obliquely with respect to the flow axis of the multiphase fluid through the pipe that is being measured. Water-cut is calculated directly from the amplitude attenuation of the microwaves passing through the multiphase fluid and the transmission of gamma rays through the multiphase fluid.
The method disclosed in the '020 patent has many limitations including but not limited to: the method is not robust—there is no solid physical basis for determining oil/water fraction purely from microwave attenuation; determining water cut based on amplitude attenuation may be inaccurate due to nonlinear attenuation effect; and the method does not provide for the use of low activity radiation sources. U.S. Pat. No. 5,101,163 (“the '163 patent) discloses measuring water fraction in an oil/water mixture by using at least one transmitting antenna and two receiving antennas. As disclosed, antennas are designed to emit and receive operating frequencies around 2.45 GHz through the multiphase fluid. The phase difference and/or the power ratio of the two received signals are determined and used with a look-up table to yield water fraction. The '163 patent discloses installing the antennas axially in such a way that one receiving antenna receives signal in the flow direction, while the other equally-spaced antenna receives its signal against the flow direction to provide for measurement of the phase difference of signals received by the two antennas, which is directly related to the flow velocity. The '163 patent does not disclose how to make corrections for instabilities in the flow due to gas nor does it disclosed how the microwave receivers' amplitude/phase difference or ratio measurements at 2.45 GHz compensate for changes in water salinity—different water salinities will cause the multiphase fluid containing the water to interact differently with the microwaves and to cause different amplitude attenuations and phase shifts.
Many of the techniques for evaluating hydrocarbon containing multiphase mixtures flowing in a pipeline have involved attempting to accurately measure the water or the oil fraction in the multiphase flow. Techniques to make such measurements, as discussed above, have included measuring electrical impedance, microwave transmission, optical attenuation, acoustic attenuation, acoustic scattering or the like across the multiphase mixture flowing in the pipeline. However, the difficulty of making such measurement and/or analyzing the properties of the multiphase mixture from such measurements is illustrated by the fact that in a 99% GVF flow with 10% water-liquid ratio, the water occupies only 0.1% of the cross-sectional area and the oil only occupies 0.9% of the cross sectional area. Therefore, to accurately measure the liquid phase of the multiphase flow using such techniques is very difficult given that the accuracy of the fraction measurement is ˜1%.
The examples above illustrate the limitations that may exist in direct measurement of phase properties of multiphase mixtures without sampling. In the hydrocarbon industry, analysis of the multiphase mixture may be necessary-desired in extreme and/or remote locations, such as down wellbores—where temperature and pressure may be very high—in subsea pipelines, in subsurface locations that may also be under the sea or the like. In such remote and/or extreme locations, it may be desirable for the analysis system to be robust, maintenance free and to provide for only limited interference with the transport of hydrocarbons in the pipelines. As such there exists a long felt need in the art for robust, versatile and effective method and system for sampling the liquid phase of a multiphase mixture flowing in a hydrocarbon transporting pipeline.